Introduction
Shale oil refers to the petroleum stored in organic-rich shales predominantly containing nano-scale pores. This abundant and widespread resource is another hot spot in unconventional exploration after shale gas [1-2]. Shale reservoirs are characterized by low porosity, low permeability and high difficulties in recovery. Large-scale multi-stage fracturing (stimulated reservoir volume-oriented, or SRV-oriented) is a necessity to form large-scale spatial fracture networks and therefore, improve the near-wellbore permeability and production capacity of wells. The progress of SRV-oriented fracturing is vital for expanding the hydrocarbon exploration range and boosting the development of shale gas and oil [3⇓⇓-6].
The exploration and development of shale oil in China still stay in the preliminary stage. Numerous breakthroughs have been made successively in the Junggar Basin [7-8], Ordos Basin [9-10], Bohai Bay Basin [11⇓-13], Qaidam Basin [14-15] and Sichuan Basin [16], with the SRV-oriented fracturing of horizontal wells serving as the main technology, and excellent development performance is delivered from the thin tight interbed sweet-spot enriched zone of some shale series. However, with the gradual scale-up of shale oil exploration and development, the proportion of high-quality reserves is declining, and the intra-source retained oil in shale, as a dominant resource, is bound to be the focus of exploration and development [17].
The exploration and development of Gulong shale oil in northern Songliao Basin represents the first large-scale attempt relating to shale oil in pure shale in China. In 2019, Well GY-YP-1, targeting the pure shale of the Cretaceous Qingshankou Formation, delivered high-rate industrial oil streams, which confirms the satisfactory potential of Gulong shale oil and marks a historical leap of continental shale from “source rock generating oil” to “reservoir rock producing oil”. However, the Gulong shale is very different in mineral composition, physical properties, oil content and producibility, from the oil shales in North America that were mainly deposited in marine or saline lake basin environment. In particular, the Gulong shale features extremely-developed laminations and foliations (up to 1000-3000 laminations per meter), and a high content of clay minerals (averaging 35.6%). Moreover, it exhibits complex occurrence and migration mechanisms of shale oil in the pore-fracture system [18-19]. Hence, the Gulong shale oil cannot be developed by simply copying the practice of volumetric fracturing process in North America or other shale oil blocks [20], unless appropriate innovative theory and technology of horizontal well multi-stage fracturing become available. This paper reviews the multiple rounds of upgrades of the hydraulic fracturing technology for the Gulong shale oil and proposes reservoir stimulation technology development suggestions in relation to the production performance of Gulong shale oil wells.
1. Geological setting
The northern Songliao Basin mainly develops two sets of shale oil reservoirs, and the Gulong shale oil mostly occurs in the second-order structural units of the Central Depression, such as the Qijia-Gulong Sag, Daqing Placanticline and Sanzhao Sag [21⇓-23]. By the maturity and hydrocarbon composition of shale oil, the Gulong shale oil can be grouped into light oil and thin oil zones. The shale oil of Qingshankou Formation mainly occurs in the first and second members of Qingshankou Formation (Qing-1 and 2 members), which is divided into 9 oil layers (Q1-Q9) from bottom to top. The Qingshankou shale oil, medium-highly mature, is now the main target for exploration and development. Forty-two wells are drilled for exploration and appraisal, including 25 vertical wells and 17 horizontal wells. Five pilot testing well groups, consisting of 58 wells, are deployed for horizontal well development. By far, all 58 wells have been completely drilled; specifically, 49 wells have been fractured, and 48 wells have been brought into production. Well GY-YP-1, a representative well, targets Q2 and Q3, and has a horizontal section of 1562 m. It yielded high-rate industrial hydrocarbon streams - the flowing oil production of 30.5 t/d and the flowing gas production of 1.30×104 m3/d - during the production test after fracturing with 82 314 m3 fluids. During the 905-d post-breakthrough production, Well GY-YP-1 contributed a cumulative production of 1.44×104 t of oil equivalent, including 1.02×104 t oil and 542×104 m3 gas, recording a major breakthrough in shale oil production. In addition, Well GY-9HC, targeting Q9, achieved flowing production after reservoir stimulation, and produced 6670 t oil or 1.09×104 t oil equivalent in the first year.
Generally, all vertical wells revealed oil flow from the 9 layers during the production test of the Gulong shale oil. Moreover, 7 layers, especially Q2, Q3 and Q4 of the lower Qing-1 Member and Q9 of the upper Qing-2 Member, were proven to deliver high production by horizontal well. Nevertheless, the production performance is highly varied among wells, and the overall production has not reached the threshold for cost-effective oil production [19]. More research is required for the fracturing technology and stimulation mechanisms to deliver large-scale beneficial development of the Gulong shale oil.
2. Development history of the fracturing technology of the Gulong shale oil
2.1. Well GY-YP-1 realized the production breakthrough
During the initial development of the Gulong shale oil, no shale oil fracturing was performed in the Daqing oilfield, where the formation conditions and reservoir physical properties remained unknown, and there was no relevant mature experience around the world for reference. Under such circumstances, researchers worked a lot on what to use for reservoir stimulation, how to perform the volumetric fracturing in horizontal wells of shale oil and how to deliver sufficient stimulated reservoir volume (SRV), with the goal of production breakthrough. The following efforts were made. With lessons learned from the fracturing of tight oil reservoirs, the long-stage multi-cluster fracturing technology with small cluster spacing was adopted. In view of the high clay mineral content and high ductility of shale oil reservoirs, the proportions of guar gum fracturing fluids were increased to create extended artificial fractures. For the developed thin dolomite barrier, acids were used to ensure vertical propagation of fractures. For tight reservoirs with low hydrocarbon flow capacity, the prepad CO2 fracturing technology was applied to deliver in-advance formation energy charging while creating complex near-wellbore fractures, since CO2 could function for increasing energy and reducing rock-breaking pressure. To solve the problems of inadequate fracture propping performance and sand production, the mixture of proppants and fibers was used for proppant injection.
The fracturing scheme of Well GY-YP-1 was designed according to the above strategies. This scheme involved 36 fracturing stages including 148 clusters, that is, 3-6 clusters in each stage, which were spaced 10 m. Given 8-16 perforations/cluster, casing fracturing was performed using soluble bridge plugs at the pump rate of 14-16 m3/min, with 18-22 m3 proppant and 600 m3 fluid injected per cluster. The running of the bridge plug encountered restrictions at the 26th fracturing stage, which was then abandoned. Ultimately, the first horizontal well of Gulong shale oil was volumetrically fractured by 35 stages with 138 clusters. In total, 82 314 m³ liquid, 3475 t CO2, 2696 kg fibers, 3063 m³ proppants, and 352 m³ acids were injected, the actual pump rate was 10.4-18.0 m³/min, the treatment pressure was 51-67 MPa, and the highest proppant ratio was 22%. The micro-seismic monitoring reveals vertical fractures with lengths of 255-568 m (Fig. 1 ).
Fig. 1. Fracture distribution in Q2 and Q3 of Well GY-YP-1 according to micro-seismic monitoring (different colors represent different micro-seismic events; the same hereinafter). |
The successful reservoir stimulation of Well GY-YP-1 in 2019 is the first application of the reservoir stimulation mode of horizontal well multi-stage multi-cluster fracturing + high-low-high viscosity liquid (or inverse mixing) injection program+ slug-type proppant injection + prepad CO2. After fracturing, high-rate hydrocarbon streams were obtained, demonstrating the development prospect and potential of the Gulong shale oil. Yet, it should be noted that this well pursues production breakthrough, but has numerous unresolved problems, such as a large treatment scale, high costs of guar gum fracturing fluids, uneven fracture propagation, and a tremendous waste of fracturing fluids attributed to slug-type proppant injection [24-25].
2.2. Cost control was preliminarily achieved in the volumetric fracturing of the No. 1 and No. 4 well groups
From early 2020 to late 2021, researchers were devoted to controlling the fracturing costs of the Gulong shale oil. They attempted to replace guar gum fracturing fluids with high-proportion slickwater and analyzed the feasibility of continuous slickwater proppant transportation in shale oil reservoirs. The fracturing practice, combined with the laboratory experimental studies of the Gulong shale oil such as rock mechanic parameter analysis, core description, bedding evaluation and storage space characterization, reveals that the restrained dimensions of artificial fractures are the main factor compromising the reservoir stimulation efficiency. Accordingly, the first upgrade of the fracturing technology was accomplished in the No. 1 and No. 4 well groups. Following the principles of reducing costs, expanding SRVs, restraining near- wellbore microfractures and far-extending main fractures, and controlling liquid production for proppant stabilization, the horizontal well field testing of the Gulong shale oil delivered continuous slickwater proppant transportation, with the slickwater proportions over 80% and the highest proppant ratio over 30%. Thus, the “slug-type proppant injection” was converted to “continuous proppant injection”, the fracturing costs of wells were effectively controlled, and the reservoir stimulation strategy featuring the predominant slickwater + small-size proppants + long fracturing stage with numerous clusters was developed. The liquid production was managed for proppant stabilization, which improves the fracture propping performance and delivers oil gain by injecting massive quartz sands. A new reservoir stimulation mode for the Gulong continental-original shale oil was therefore launched.
At the No. 1 and No. 4 well groups, the reservoir stimulation was performed with 7-10 clusters in each fracturing stage, which were spaced 7 m, by way of extreme limited-entry fracturing. The perforating was designed with the phase angle of 60°, the penetration of 0.3 m, the shot density of 6 shots/m, and an identical perforation diameter, which ensured one shot upward and one shot downward along the vertical direction. The slope perforating guaranteed that fractures could initiate at each cluster. The pump rate was 14-16 m3/min, and the average liquid injection intensity was controlled at 20-25 m3/min in each well to greatly reduce the consumption of fracturing fluids. To maximize the opening of bedding seams, the slickwater proportion was increased to 80% and the proppant/liquid ratio was raised to 1:919. The flow conductivity of fractures at different scales required for different permeability was calculated via simulation. Moreover, the flow conductivity of fractures was investigated depending upon the characteristics of fractures at different scales, proppant embedment, proppant concentration and proppant combinations. It was finally determined to use the combination of 212/109 μm (70/140 mesh) and 380/212 μm (40/70 mesh) quartz sands with a proportion of 8:2, and increase the proppant injection intensity to 2.3-3.0 m3/m. This marks a breakthrough from the slug-type proppant injection based on guar gum fracturing fluids in Well GY-YP-1 and delivers continuous slickwater proppant transportation, with a maximum proppant ratio of up to 32% and considerable reduction of treatment costs.
To maximize the SRV of the producible oil box, the zipper fracturing process with inter-well staggered fracture placement was designed. However, the zipper fracturing was not truly performed, due to the wellhead and underground layouts and some operation difficulties. The positive effects of stress interference were not sufficiently exploited. It was hard for slickwater to build up pressure and extend fractures through different layers, which resulted in a limited fracture height. Moreover, the excessive pursuit of “liquid control for proppant stabilization” considerably impacted the SRV. The micro-seismic monitoring shows that the fracture lengths are mostly 200-300 m (Fig. 2 ), which notably affects the production capacity of horizontal wells.
Fig. 2. Fracture distribution in Q2 of the No. 1 well group according to the micro-seismic monitoring. |
2.3. The planar-control horizontal well field testing recorded a sustained improvement in reservoir stimulation performance
Based on the fracturing success of the No. 1 and No. 4 well groups and the lesson of insufficient reservoir stimulation, a batch of planar-control horizontal wells were deployed for field testing. The average cluster spacing was 7 m, and each stage had 7 clusters. The slope and extreme limited-entry approaches were combined for perforating. The volume and combination proportions of fracturing fluids were moderately adjusted. The average liquid injection intensity of wells was raised to 30-38 m3/m; the proportion of slickwater was reduced to 20%-50%; the continuous proppant injection intensity was about 2.67 m3/m. The combinations of proppants were also field-tested. The large-diameter proppants of 830/380 μm (20/40 mesh) were introduced, and the proportion of the small-, medium- and large-diameter proppants was 1.5:5.5:3.0.
There were totally 17 planar-control horizontal wells, which all produced oil. Ten wells in the core zone of the Gulong Sag yielded the average production rates above 15 t/d under the constant-pressure scheme, and kept stable production in the 234-905 d testing. They include 4 wells producing from Q9, 5 wells from Q1-Q4, and 1 well from Q5-Q6. Well GY1-1001H-Q2, also targeting Q2, was taken as an example for comparison. In this well, the 2500 m horizontal section was fractured by 45 stages with 328 clusters, and using 6.1×104 m3 fluids and 5430 m3 proppants. The micro-seismic monitoring shows the fractures of 214-291 m long (Fig. 3 ). The flowback rate was 0.68%, upon the oil breakthrough. With a 5-mm choke for flush production, the maximum production reached 22.7 t/d oil and 3886 m3/d gas. During 381 d of post-oil breakthrough production, the cumulative oil production was 4269.2 t, and the cumulative gas production was 57×104 m3, registering a total oil equivalent of 4723.3 t.
Fig. 3. Fracture distribution of Well GY1-1001H-Q2 according to the micro-seismic monitoring. |
Given the insufficient fracture conductivity of the No. 1 and No. 4 well groups, the proportion of 380/212 μm (40/70 mesh) proppant was increased in the planar-control horizontal well field testing, and 830/380 μm (20/40 mesh) proppant was added. Moreover, the proportion of guar gum fracturing fluid was properly raised to ensure a desirable proppant transportation distance. The micro-seismic monitoring shows that the fracture length is mainly 200-300 m, comparable to those of the No. 1 and No. 4 well groups, and yet effectively supported the initial high production and long-term stable production. However, the field monitoring reveals severe inter-cluster interference within the fracturing stage and uneven reservoir stimulation, since these wells commonly adopted a fracturing design with 7 clusters in each stage. In addition, compared with the No. 1 and No. 4 well groups, the SRVs of these wells were seen with no considerable expansion.
2.4. The field testing of the No. 2 and No. 3 well groups demonstrated overall SRV expansion of wells
In early 2022, with the progress of the geological and engineering researches on the Gulong shale oil, researchers realized that the current injection volume of slickwater could still lead to excessively complex near-wellbore fractures impacting SRVs of wells and well groups; moreover, high-viscosity fluids were conducive to vertical propagation of fractures and extension of fracture lengths. Hence, a new round of attempts was started. However, high-viscosity fluids are unfavorable for creating complex fractures, the high-low-high viscosity liquid (inverse mixing) injection process should be further upgraded, and the proportions of high- and low-viscosity fracturing fluids should be further determined. The field testing of the No. 2 and No. 3 well groups accomplished the second upgrade of the fracturing technology for the Gulong shale oil. Thus, the main fracturing technology featuring high-low-high viscosity liquid injection + predominant high-viscosity fluid + large-diameter proppant + prepad CO2 + fewer clusters in one stage was developed. It delivers desirable fracture complexity while expanding the SRV of wells. After fracturing, the producibility of shale oil is greatly improved.
In terms of the fluid system, the investigation of the fluid flow laws in shale reservoirs clarifies that a longer artificial fracture is favorable for the liquid supply of the matrix to fractures and maintaining stable pressure. Furthermore, to maximize the SRV of wells, the liquid injection intensity was increased to 30-40 m3/m, and the proppant injection intensity was adjusted to 2.0-2.3 m3/m, after simulation and optimization of multiple schemes. The inverse mixing practice of fluids injection was developed, that is, high-viscosity fracturing fluid is used to expand the SRV during the initial operation, low-viscosity slickwater is used to connect foliations for increasing fracture complexity during the intermediate operation stage, and high-viscosity fracturing fluid is injected again for continuous proppant transportation during the late operation. The proportion of guar gum in the fracturing fluid system was lifted to 80%. At the No. 3 well group, the active water system-based fracturing technology was further tested to expand SRVs, since the active water with high friction is believed to be capable of increasing the fracture net pressure and connecting the wellbore with more natural fractures.
For the unclear fracture initiation mechanism in the case of a long fracturing stage with multiple clusters and the excessive erosion of some perforation holes, it was determined after simulations of multiple schemes that the combination of fewer (2-4) clusters within one stage and a limited perforation number (48) is more helpful for even fracture initiation. Horizontal foliation is well developed in the Gulong shale. Excessively small cluster spacing can result in higher difficulties in fracture initiation, which compromises the SRV, and inter-fracture interference during production, which accelerates the pressure decline inside fractures. Accordingly, the cluster spacing was increased to 15 m.
To improve the vertical proppant placement profile and expand the area of effective propped fracture, the proportions of medium- and large-diameter proppants were increased to 85%, and the proportion among the small-, medium- and large-diameter proppants was changed to 1.5:5.5:3.0. Meanwhile, the steel grade of casing used in shale oil wells was upgraded, and the pump rate was lifted to 18-20 m3/min, so as to increase the fracture net pressure and effectively promote the fracture initiation along the vertical and horizontal directions and also fracture complexity.
In addition, the stimulation intervals were finely divided according to the geomechanical parameters and oil content of the No. 2 and No. 3 well groups. The reservoir intervals with similar indexes were stimulated simultaneously to facilitate uniform fracture extension. Deepened insights into natural fractures were obtained, and naturally-fractured intervals were placed as the focus of reservoir stimulation to raise the post-frac production of wells. The stress variation of the reservoir was considered in the operation. The well group fracturing sequence was optimized depending upon the fracturing trunk capability, to positively exploit stress interference attributed to pore pressure growth to expand the SRV.
The micro-seismic monitoring reveals that the fracture length is 300-400 m at the No. 2 well group (Fig. 4 ) and 362-421 m at the No. 3 well group (Fig. 5 ). The SRV is considerably expanded. However, due to the high clay mineral content and high foliation development of the Gulong shale, the resultant reservoir stimulation performance still fails to deliver cost-effective recovery of shale oil. Besides, the production performance is observed with the slow oil cut growth and the stable oil cut is below 50%, which means that the fracture complexity shall be further improved. Hence, another upgrade of the fracturing technology is demanded to improve the reservoir stimulation performance.
Fig. 4. Fracture distribution of the No. 2 well group according to the micro-seismic monitoring. |
Fig. 5. Fracture distribution in some fracturing stages of Q2 in the No. 3 well group according to the micro-seismic monitoring. |
3. Well performance of the Gulong shale oil
3.1. Oil cut of shale oil wells
The Gulong shale reservoir features complex geology. By far, multiple rounds of upgrades have been performed for the fracturing technology, and field testing of each well group and planar-control horizontal well has been carried out to investigate the effects of numerous factors. Due to the drilled target layer and flowback/production scheme, the planar-control horizontal wells and well groups are highly differentiated in production performance. Nonetheless, the overall production performance of fractured wells still reveals a gradual improvement in the fracturing technology applicability. As shown in Fig. 6 , the oil cut of shale oil wells grows considerably. Besides, the production well of the No. 2 well group delivers high-oil-cut production with low flowback rate, which confirms the great importance of the SRV to the production of shale oil wells. The well-controlled reserves are increased. More hydrocarbons can migrate toward the near-wellbore zone via fractures, and massive hydrocarbons accumulate near the wellbore, which is the main factor leading to an increase in oil cut. The post-frac production rapidly sees oil with a low flowback rate, and the oil cut is high during production. Under such circumstances, massive fracturing fluids are left in the reservoir, which avoids rapid dissipation of formation energy and helps to improve the ultimate recovery factor of wells [26].
Fig. 6. Oil cut vs. flowback rate of shale oil wells |
3.2. Pressure drop of shale oil wells during post-frac soaking
The Gulong shale reservoir has extremely developed foliation. The post-frac soaking (shut-in) process of shale oil wells is in favor of near-wellbore energy release. Driven by the pressure difference, fractures penetrate foliation weak planes and migrate via fractures toward the distal zone far away from the wellbore. A larger range of the reservoir is involved, which increases the well-controlled reserves and well production. Given this, the pressure decline during soaking directly affects the subsequent flowback/production performance. The pressure decline of the Gulong shale oil wells during soaking (Fig. 7 ) shows that after upgrades of the fracturing technology, the pressure decline rate of the No. 3 well group during soaking is higher than that of the No. 1, No. 2 and No. 4 well groups and similar to that of the planar-control horizontal wells. This indicates the expansion of the controlled reservoir volume of the No. 3 well group, and that the expanded SRV promotes the even spreading of energy and the swept range of fracturing fluids. It indirectly confirms the applicability of the current fracturing technology, in terms of maximizing the SRV of wells.
Fig. 7. Pressure decline of shale oil wells during post-frac soaking. |
3.3. Prepad CO2 fracturing performance of shale oil well
At present, 71 shale oil wells in total in the Gulong Sag adopt the prepad CO2 fracturing. The average CO2 injection of wells is 2211 t, and 3475 t of CO2 is injected into Well GY-YP-1 during fracturing. During the nearly three-year production, 610.84 t of CO2 flows back, and thus, 2864.16 t of CO2 is left underground. The stage (temporary) CO2 sequestration is 82.42%, validating the good geological sequestration performance of the prepad CO2 fracturing.
Comparative testing was performed in the No. 2 well group for the cases with and without prepad CO2 fracturing. The results are summarized below. For wells with CO2 fracturing, the average casing pressure is 13.62 MPa and the average flowback rate is 11.42% upon oil breakthrough (Fig. 8 ); the former is higher and the latter is lower than those of wells without CO2 fracturing. In Well GY2-Q2-H1, after CO2 was injected into the first 21 stages, the average main treatment pressure reduced by 3.4 MPa, which expands the pressure safety window of fracturing operations and validates the improvement of shale oil well fracturing performance attributed to the prepad CO2.
Fig. 8. Casing pressure upon oil breakthrough for wells in the No. 2 well group with and without prepad CO2 fracturing. |
4. Suggestions for the development of the Gulong shale oil fracturing technology
Due to the well-developed laminations and foliation (bedding at different scales), soft rock and small difference between the horizontal principal stresses of the Gulong shale, the hydraulic fracturing tends to create a complex fracture network resembling the outdoor bar-type TV antenna [19] (a main fracture with multiple perpendicular branch fractures that have different lengths). After multiple fracturing campaigns of the Gulong shale oil, the main fracturing technology is upgraded continuously. However, the near-wellbore fractures are still extremely complicated, due to foliation seams. Massive liquid is trapped around the wellbore, which severely restrains the propagation of fractures toward the deeper reservoir and greatly impacts the SRV. This is an essential restraint on the cost-effective development of the Gulong shale oil. Given the aforementioned, the applicability of the fracturing technology to reservoirs should be improved depending on the geological conditions and physical properties of the shale reservoirs. To maximize the fracture-controlled reserves, more efforts must be taken to figure out the way for improving the fracture length and height in shale oil reservoirs. The fracturing design strategy of “restraining near-wellbore complex microfractures and far-extending main fractures” (Fig. 9 ) is critical. Specifically, engineering techniques are applied to suppress the growth of microfractures and fracture complexity in the near-wellbore zone, and in the meantime, improve the distal extension of fractures and the proppant transportation distance to ensure long-term fracture conductivity. The following aspects should be considered in practice.
Fig. 9. Performance comparison between conventional fracturing and fracturing highlighting “restraining near-wellbore microfractures and far-extending main fractures”. |
4.1. Suppress the propagation of near-wellbore microfractures
The application of low-viscosity fracturing fluid enables artificial fractures to propagate parallel to the foliation and thus opens the foliation seams to promote fracture complexity. Meanwhile, the high-viscosity fracturing fluid can greatly reduce fluid leak-off in foliation and natural fractures and prevent the excessive propagation of near-wellbore complex fractures. These increase the fracture net pressure and help the main artificial fracture to effectively propagate along both the vertical and horizontal directions so as to expand the SRV [27]. For the purpose of restraining near-wellbore microfractures and far-extending main fractures, it is suggested to inject high-viscosity guar gum fracturing fluid before the main part of the treatment to expand the fracture width and improve the cake-forming of fracturing fluid. As the desired pump rate is reached, the slug of silt-sized proppants is injected to plug near-wellbore complex microfractures and control the near-wellbore fracture complexity. After the main fracture channel is formed, slickwater is injected at a high pump rate to increase the continuous proppant transportation distance and fracture complexity, and effectively expand the range of the distal complex fractures.
In addition, considering the planar and vertical heterogeneity of the Gulong shale oil reservoir, the applications of guar gum fracturing fluid and slickwater should be customized depending upon the geological characteristics of the shale reservoir. For intervals with well-developed foliation and natural fractures, the injection volume of guar gum fracturing fluid should be increased to pursue the fracture length and height. For intervals with no development of foliation and natural fractures, the proportion of slickwater should be appropriately raised. By doing so, the moderate prepad of guar gum fracturing fluid is used to open fractures, while the slickwater promotes the fracture complexity.
4.2. Improve the CO2 injection program
Inferior physical properties (low porosity and low permeability), rapid production decline and low primary recovery factor are prominent in shale oil reservoirs. Injecting CO2 into reservoirs during fracturing is an effective way to improve the production of shale oil wells and the ultimate recovery factor. Injected CO2 can efficiently improve the reservoir permeability and the crude oil flow capacity [28-29]. However, CO2 often reaches the supercritical state under reservoir conditions and features low viscosity and low interfacial tension. Injecting prepad CO2 at high pressure and high pump rate is highly likely to create complex fractures in the near-wellbore zone [30], which results in higher difficulties in forming main fractures and further restrains the SRV. The difficulties in proppant injection are also stimulated, which is unfavorable for the implementation of the strategy of restraining near-wellbore complex microfractures and far-extending main fractures. To sum up, it is recommended to inject CO2 at a lower pump rate, upon creating the main fracture with the previous guar gum fracturing fluid. This avoids forming complex fractures in the near-wellbore zone and gives full play to formation energy increment and drainage enhancement by CO2.
4.3. Reasonably control the shot density
In the case of multi-cluster perforating and fracturing in horizontal wells, the induced stress interference between fractures is severe. Fractures near some perforation clusters in horizontal wells fail to deliver effective extension, and numerous ineffective (non-productive) perforation clusters are observed after fracturing. The multi-cluster perforating and fracturing are commonly facing low ratios of productive clusters [31].
The limited-entry perforating technology can effectively promote the uniform fracture initiation and propagation of multiple clusters within one fracturing stage of the horizontal well. Numerical simulation was performed to investigate the multi-fracture propagation performance of different perforation clusters for a seven-cluster stage, in cases of 77, 40 and 28 perforations (Fig. 10 ). The results show that with fewer perforations, the flow rate and friction of a single perforation are considerably improved. The flow rate distribution across perforation clusters becomes more uniform, which is favorable for multi-fracture uniform propagation.
Fig. 10. Multi-fracture propagation geometry in cases of different perforation numbers. |
4.4. Optimize the proppant combination
Proppants are vital for the flow conductivity of artificial fractures. The artificial fractures in the Gulong shale oil reservoir feature a complex geometry, and the flow of fracturing fluid is split as it is injected into the formation. In branch fractures, the flow velocity of fracturing fluid is gradually reduced, and so is the proppant-carry capability and flushing over proppant banks. This is adverse for the proppant transportation and placement. The small-diameter proppants are lighter in mass and smaller in volume, and thus are easier to be entrained deep into the fractures by the fracturing fluid to effectively extend the length of propped fractures. However, shale oil wells are prone to severe sand production, in the case of a large injected volume of small-diameter proppants. This is harmful to the production of shale oil wells.
Therefore, an appropriate volume of small-diameter proppants at a higher injection rate is recommended for the early operation stage to offset the reduction of the proppant-carrying capacity attributed to the flow splitting in complex fractures. By doing so, the proppant bank equilibrium height is lowered, and the distance from the proppant bank front to the fracture entrance is extended, so as to reduce the possibility of screening out inside fractures. Furthermore, it is advised to inject medium- diameter proppants during the intermediate operation stage, to lift the proppant bank equilibrium height and facilitate effective fracture propping. At the end of proppant injection, a tail of large-diameter proppants is recommended to deal with the proppant embedment - specifically, increase the flow conductivity at the fracture entrance and prevent proppant backflow. In addition, since the fractures of the Gulong shale are rather coarse and have intensive fracture tip effects, it is suggested to use some ceramic proppants as large-diameter proppants to decrease the overall crushing rate of proppants.
4.5. Properly optimize the well pattern and spacing
The well group fracturing is performed with given boundary conditions, and the well pattern and spacing have important effects on inter-well interference. The investigation of the optimal well pattern and spacing is currently an important field of research for the cost-effective development of shale oil.
Inter-well interference is observed for multiple times during the well group fracturing of the Gulong shale oil. However, inter-well interference during fracturing does not necessarily lead to inter-well inference of shale oil wells during production. This is because inter-well connection may not occur during production, although pressure interference happens during the fracturing operation with high injection pressure and pump rate, especially with a limited proppant transportation distance. The inter-well production interference should be more attributed to the well pattern and spacing as well as the pore-throat connectivity of the reservoir.
4.6. Discreetly apply the fiber-assisted injection technology
Post-frac sand production is frequently seen in the Gulong shale oil wells, which impacts the production. Therefore, fiber-assisted injection technology is often used for the proppant transportation of fracturing fluid. Specifically, fibers and quartz sands are mixed and injected. Under such circumstances, fibers form network structures to prevent the backflow of quartz sands into the wellbore, entrained by flowback fluids during the flowback process. However, the presence of fibers in the shale reservoir may result in flow plugging and trapping of massive fracturing fluids in the near-wellbore zone. The performed fracturing, therefore, focuses on stimulating the near-wellbore zone, which deviates from the strategy of restraining near-wellbore complex microfractures and far-extending main fractures. Hence, caution should be exercised for applications of fibers.
5. Conclusions
On the basis of the field testing of exploration and appraisal wells and horizontal wells, the fracturing technology of the Gulong shale oil in the Songliao Basin has experienced multiple rounds of upgrades, which preliminarily delivers good reservoir stimulation performance. However, the fracture geometry and the rationality of the reservoir stimulation engineering practice are still important topics for future research.
To deepen our understanding of the fracture geometry, applications of more advanced fracturing monitoring techniques are required to integrate the advantages of different techniques and deliver dynamic monitoring of fracturing to track the full-lifecycle performance of shale oil wells and realize high-quality resource recovery.
Furthermore, the fracturing design should be geology-engineering integrated and case-specific. Reservoir stimulation technologies for different recovery modes should be developed. Future research should be done to deepen the understanding of the engineering sweet spots, in accordance with different development requirements. The differences of reservoir stimulation among sweet spots should be analyzed to deliver more adapted fracturing treatment, so as to increase the fracture-controlled reserves and the well production.
As a representative of continental shale oil, the Gulong shale oil testifies the upgrades of the fracturing technology via inheriting and innovative applications, from the breakthrough of Well GY-YP-1, to field testing of the No. 1 and No. 4 well groups, planar-control horizontal wells, and the No. 2 and No. 3 well groups. “Restraining near- wellbore complex microfractures and far-extending main fractures” has always been the core strategy of reservoir stimulation of the Gulong shale oil and is also the vital goal for cost-effective shale oil development.
More investigations are demanded for the CO2 injection volume and program. Next, the affected volume and range of prepad CO2 should be clarified, and the lower limit of producible shale oil be calculated. The effects of CO2 on the threshold flow pressure gradient of shale oil should be identified, and the injected volume should be optimized.
The horizontal well group fracturing of shale oil reservoir has an extremely large scale of treatment, and consumes tremendous quantities of fracturing fluids, proppants and additives. The quality of the injected materials is vital for the fracturing performance of shale oil wells. Systematic and strict quality control on the injected materials should be performed to ensure the satisfactory quality of products.
Acknowledgments
This research is funded by the Heilongjiang Province “Open Competition for Best Candidates” Projects “Research on Phase State, Seepage Mechanisms and Geology-Engineering-Integrated Reservoir Stimulation of Gulong Shale Oil” and “Research on Diagenetic Dynamic Evolution and Pore-Fracture Coupling of Gulong Shale Oil Reservoirs”. Sincere thanks are given to relevant experts and researchers of the Academician Workstation, Shale Oil Exploration and Development Headquarter, Production Technology Institute, and Exploration & Development Research Institute of Daqing Oilfield for guidance and help during the research work and preparation of this manuscript.